Fluids used in the drilling, completion, stimulation, and remediation of subterranean oil and gas wells are known. It will be appreciated that within the context herein, the term “fluid” also encompasses “drilling fluids”, “completion fluids”, “workover fluids”, “servicing fluids”, “stimulation fluids”, and “remediation fluids”.
Drilling fluids are typically classified according to their base fluid. In water-based fluids, solid particles are suspended in a continuous phase consisting of water or brine. Oil can be emulsified in the water, which is the continuous phase. “Water-based fluid” is used herein to include fluids having an aqueous continuous phase where the aqueous continuous phase can be all water or brine, an oil-in-water emulsion, or an oil-in-brine emulsion. Brine-based fluids, of course are water-based fluids, in which the aqueous component is brine. a
Oil-based fluids are the opposite or inverse of water-based fluids. “Oil-based fluid” is used herein to include fluids that are completely oil, fluids having a non-aqueous continuous phase where the non-aqueous continuous phase is all oil, a non-aqueous fluid, a water-in-oil emulsion, a water-in-non-aqueous emulsion, a brine-in-oil emulsion, or a brine-in-non-aqueous emulsion. In oil-based fluids, solid particles are suspended in a continuous phase consisting of oil or another non-aqueous fluid. Water or brine can be emulsified in the oil; therefore, the oil is the continuous phase. In oil-based fluids, the oil may consist of any oil or water-immiscible fluid that may include, but is not limited to, diesel, mineral oil, esters, refinery cuts and blends, or alpha-olefins. Oil-based fluid as defined herein may also include synthetic-based fluids or muds (SBMs), which are synthetically produced rather than refined from naturally occurring materials. Synthetic-based fluids often include, but are not necessarily limited to, olefin oligomers of ethylene, esters made from vegetable fatty acids and alcohols, ethers and polyethers made from alcohols and polyalcohols, paraffinic and/or aromatic hydrocarbons, alkyl benzenes, terpenes and other natural products and mixtures of these types.
For some applications, in particular for the use of some wellbore imaging tools, it is important to reduce the electrical resistivity (which is equivalent to increasing the electrical conductivity) of the oil-based fluid as the electrical conductivity of the fluids has a direct impact on the image quality. Certain resistivity logging tools, such as high resolution LWD tool STARTRAK™, available from Baker Hughes Inc, require the fluid to be electrically conductive to obtain the best image resolution. Water-based fluids, which are typically highly electrically conductive with a resistivity less than about 100 Ohm−m, are typically preferred for use with such tools in order to obtain a high resolution from the LWD logging tool.
However, oil based fluids are preferred in certain formation conditions, such as those with sensitive shales, or high pressure high temperature (HPHT) conditions where corrosion is abundant. Oil-based fluids are a challenge to use with high resolution resistivity tool, e.g. STARTRAK™, because oil-based fluids have a low electrical conductivity (i.e. high resistivity). It would be highly desirable if fluid compositions and methods could be devised to increase the electrical conductivity of the oil-based or non-aqueous-liquid-based drilling, completion, production, and remediation fluids and thereby allow for better utilization of resistivity logging tools.
There are a variety of functions and characteristics that are expected of completion fluids. The completion fluid may be placed in a well to facilitate final operations prior to initiation of production. Completion fluids are typically brines, such as chlorides, bromides, formates, but may be any non-damaging fluid having proper density and flow characteristics. Suitable salts for forming the brines include, but are not necessarily limited to, sodium chloride, calcium chloride, zinc chloride, potassium chloride, potassium bromide, sodium bromide, calcium bromide, zinc bromide, sodium formate, potassium formate, ammonium formate, cesium formate, and mixtures thereof.
Chemical compatibility of the completion fluid with the reservoir formation and fluids is key. Chemical additives, such as polymers and surfactants are known in the art for being introduced to the brines used in well servicing fluids for various reasons that include, but are not limited to, increasing viscosity, and increasing the density of the brine. Water-thickening polymers serve to increase the viscosity of the brines and thus retard the migration of the brines into the formation and lift drilled solids from the wellbore. A regular drilling fluid is usually not compatible for completion operations because of its solids content, pH, and ionic composition. Completion fluids also help place certain completion-related equipment, such as gravel packs, without damaging the producing subterranean formation zones. Modifying the electrical conductivity and resistivity of completion fluids may allow the use of resistivity logging tools for facilitating final operations.
A stimulation fluid may be a treatment fluid prepared to stimulate, restore, or enhance the productivity of a well, such as fracturing fluids and/or matrix stimulation fluids in one non-limiting example.
Servicing fluids, such as remediation fluids, workover fluids, and the like, have several functions and characteristics necessary for repairing a damaged well. Such fluids may be used for breaking emulsions already formed and for removing formation damage that may have occurred during the drilling, completion and/or production operations. The terms “remedial operations” and “remediate” are defined herein to include a lowering of the viscosity of gel damage and/or the partial or complete removal of damage of any type from a subterranean formation. Similarly, the term “remediation fluid” is defined herein to include any fluid that may be useful in remedial operations.
Before performing remedial operations, the production of the well must be stopped, as well as the pressure of the reservoir contained. To do this, any tubing-casing packers may be unseated, and then servicing fluids are run down the tubing-casing annulus and up the tubing string. These servicing fluids aid in balancing the pressure of the reservoir and prevent the influx of any reservoir fluids. The tubing may be removed from the well once the well pressure is under control. Tools typically used for remedial operations include wireline tools, packers, perforating guns, flow-rate sensors, electric logging sondes, etc.
A drill-in fluid may be used exclusively for drilling through the reservoir section of a wellbore successfully, which may be a long, horizontal drainhole. The drill-in fluid may minimize damage and maximize production of exposed zones, and/or facilitate any necessary well completion. A drill-in fluid may be a fresh water or brine-based fluid that contains solids having appropriate particle sizes (salt crystals or calcium carbonate) and polymers. Drill-in fluids may be aqueous or non-aqueous. Filtration control additives and additives for carrying cuttings may be added to a drill-in fluid.
It would be desirable if the aforementioned fluid compositions and methods for using such fluids could be tailored to improve the electrical conductivity of drilling fluids, completion fluids, stimulation fluids, drill-in fluids, and servicing fluids, and thereby enhance the performance of downhole tools, such as resistivity logging tools in one non-limiting example.